In the recovery of oil from oil-bearing reservoirs, it is usually possible to recover only minor portions of the original oil in place by the so-called primary recovery methods Which utilize only the natural forces present in the reservoir. A variety of supplemental recovery techniques have been employed in order to increase the recovery of oil from subterranean reservoirs. The most widely used supplemental recovery technique is waterflooding which involves the injection of water into the reservoir. As the water moves through the reservoir, it acts to displace oil therein to a production system composed of one or more wells through which the oil is recovered.
It has long been recognized that factors such as the interfacial tension between the injected water and the reservoir oil, the relative mobilities of the reservoir oil and injected-water, and the wettability characteristics of the rock surfaces within the reservoir are factors which influence the amount of oil recovered by waterflooding. It has been proposed to add surfactants to the flood water in order to lower the oilwater interfacial tension and/or alter the wettability characteristics of the reservoir rock. Processes which involve the injection of aqueous surfactant solutions are commonly referred to as surfactant waterflooding or as low tension waterflooding, the latter term having reference to the mechanism involving the reduction of the oil-water interfacial tension. Also, it has been proposed to add viscosifiers such as polymeric thickening agents to all or part of the injected water in order to increase the viscosity thereof, thus decreasing the mobility ratio between the injected water and oil and improving the sweep efficiency of the waterflood.
Many waterflooding processes have employed anionic surfactants. One problem encountered in water-flooding with certain of the anionic surfactants such as the petroleum sulfonates is the lack of stability of these surfactants in so-called "hard water" environments. These surfactants tend to precipitate from solution in the presence of relatively low concentrations of divalent metal ions such as calcium and magnesium ions. For example, divalent metal ion concentrations of about 50-100 ppm and above usually tend to cause precipitation of the petroleum sulfonates.
Nonionic surfactants, such as polyethoxylated alkyl phenols, polyethoxylated aliphatic alcohols, carboxylic esters, carboxylic amides, and polyoxyethylene fatty acid amides, have a somewhat higher tolerance of polyvalent ions such as calcium or magnesium than do the more commonly utilized anionic surfactants. While it is technically feasible to employ a nonionic surfactant solution to decrease the interfacial tension between the injected aqueous displacing medium and petroleum contained in some limestone formations, such use is generally not economically feasible for several reasons. Nonionic surfactants are not as effective on a per mole basis as are the more commonly used anionic surfactants and, additionally, the nonionic surfactants generally have a higher cost per unit weight than do the anionic surfactants. Nonionic surfactants usually exhibit a reverse solubility relationship with temperature and become insoluble at temperatures of above their cloud points making them ineffective in many oil formations. Nonionic surfactants that remain soluble at elevated temperatures are generally not effective in reducing interfacial tension. Moreover, nonionic surfactants usually hydrolyze at temperatures above about 75.degree. C.
The use of certain combinations of anionic and nonionic surfactant to combat hard water formations has also been suggested. For example, U.S. Pat. No. 3,811,505 discloses the use of alkyl or alkylaryl sulfonates or phosphates and polyethoxylated alkyl phenols. U.S. Pat. No. 3,811,504 discloses the use of three component mixture including an alkyl or alkylaryl sulfonate, an alkyl polyethoxy sulfate and a polyethoxylated alkyl phenol. U.S. Pat. No. 3,811,507 discloses the use of a water-soluble salt of a linear alkyl or alkylaryl sulfonate and a polyethoxylated alkyl sulfate.
Cationic surfactants such as quaternary ammonium salts, and derivatives of fatty amines and polyamines, have also been used. However, these compounds have the disadvantage of substantivity or attraction, especially towards silicate rock, and they lose their activity by adsorption.
The use of certain amphoteric surfactants which function as cationics in acid media and become anionic when incorporated in alkaline systems has been suggested. For example, U.S. Pat. No. 3,939,911 discloses a surfactant waterflooding process employing a three-component surfactant system. This surfactant system includes an alkyl or alkylaryl sulfonate such as an ammonium dodecyl benzene sulfonate, a phosphate ester sulfonate, and a sulfonated betaine such as a C.sub.12 -C.sub.24 alkylamido C.sub.1 -C.sub.5 alkane dimethylammonium propane sulfonate.
The use of hydrocarbyl-substituted polyoxyalkylene sulfonates is disclosed, for example, in U.S. Pat. Nos. 3,916,994; 4,181,178; 4,231,427; 4,269,271; 4,270,607; 4,296,812; 4,307,782; 4,316,809; 4,485,873; and 4,478,281.
The use of thickening agents to increase the viscosity of injected water, normally to a value of at least equal, to that of the reservoir oil, in order to arrive at a favorable mobility ratio between the oil and water and increase the macroscopic displacement efficiency of waterflood is known. Examples of such thickeners or mobility control agents are polysaccharides such as xanthan gum, which are available from Kelco Company under the tradename "Kelzan", and partially hydrolyzed polyacrylamides available from the Dow Chemical Company under the tradename "Pusher".
U.S. Pat. No. 4,554,974 discloses an enhanced oil recovery method employing betaine amphoteric surfactants in combination with high molecular weight homopolysaccharide gum thickeners in a waterflood. The waterflood can be followed by a thickened buffer slug and then an aqueous flooding medium to displace the oil toward a production well.
A paper by W. R. Foster entitled "A Low-Tension Waterflooding Process", Journal of Petroleum Technology, Vol. 25, Feb. 1973, pp. 205-210, describes a technique involving the injection of an aqueous solution of petroleum sulfonates within designated equivalent weight ranges and under controlled conditions of salinity. The petroleum sulfonate slug is followed by a thickened water slug which contains a water-soluble biopolymer. This thickened water slug is then followed by a field brine driving fluid which is injected as necessary to carry the process to conclusion.
A number of tests employing polymeric thickeners in surfactant waterflooding have been reported in the literature. M. S. French et al and H. J. Hill et al report the use of 1.3% by weight petroleum sulfonate and 0.5% by weight sodium tripolyphosphate, and a partially hydrolyzed polyacrylamide polymer in a 9250 ppm TDS brine solution. M. S. French et al, "Field Test of an Aqueous Surfactant System for Oil Recovery, Benton Field, Ill.", J. Pet. Tech., February, 1973, pp. 195-204; and H.J. Hill et al, "Aqueous Surfactant Systems for Oil Recovery", J. Pet. Tech , February, 1973, pp. 186-194. H. H. Ferrell et al report pilot studies using 2.5% of a mixture of synthetic and petroleum sulfonates, 3% isobutyl alcohol and a biopolymer in a 1.0% NaCl brine solution. H. H. Ferrell et al, "Analysis of Low-Tension Pilot at Big Muddy Field, Wyo.", SPE/DOE 12683 (1984). H. H. Ferrell et al report field tests using 3.0% alkyl benzene sulfonate, 5% isobutyl alcohol and partially hydrolyzed polyacrylamide in about 6000 ppm TDS brine solution. H. H. Ferrell et al, "Progress Report: Big Muddy Field Low-Tension Flood Demonstration Project With Emphasis on Injectivity and Mobility", SPE/DOE 12682 (1984). J. R. Bragg et al report pilot studies using 2.3% of a hardness tolerant surfactant and a biopolymer in formation brine. J. R. Bragg et al, "Loudon Surfactant Flood Pilot Test", SPE/DOE 10862. D. L. Taggart et al report the use of 3.86% petroleum sulfonate, 1.25% isobutyl alcohol and partially hydrolyzed polyacrylamide in a 1.2% NaCl brine solution. D. L. Taggart et al, "Sloss Micellar/Polymer Flood Post Test Evaluation Well", SPE/DOE 9781 (1981). See also, S. P. Gupta, "Composition Effects on Displacement Mechanisms of the Micellar Fluid Injected in the Sloss Field Test", SPE 8827 (1980); S. P. Gupta, "Dispersive Mixing Effects on the Sloss Field Micellar System", SPE/DOE 9782 (1981); J. L. Wanosik et al, "Sloss Micellar Pilot: Project Design and Performance", SPE 7092 (1978); P. B. Basan et al, "Important Geological Factors Affecting the Sloss Field Micellar Pilot Project", SP 7047 (1978).
A disadvantage with most surfactant-polymer waterfloods is that chemicals are prepared off-site, and then shipped, generally long distances, to the site of use. The shipment of such large quantities of materials containing large volumes of water is both burdensome and expensive.
Furthermore, various problems may be encountered when attempting to create low tension, high viscosity fluids by on-site preparation methods. These problems include: the relatively high costs and difficulties associated with storing large quantities of several different additives (e.g., surfactants, polymeric thickeners, etc.); control problems associated with maintaining desired ratios of additives in the fluid to be injected; and the relatively short shelf life of additive mixtures that are currently available.
Stability of the viscosifying characteristics of polymer-thickening agents is not a new problem. U.S. Pat. No. 3,953,341 discloses a method of modifying acrylate polymers through a methylolation process which enhances stability for the polymers used in enhanced oil recovery techniques U.S. Pat. No. 4,517,101 discloses that biopolymers, particularly xanthan gum, may be modified by methylation of the polymer itself to reduce the biodegradability of the polymer in an enhanced oil recovery flooding process. Others have modified the polymer structure to alter various properties. U.S. Pat. No. 4,639,322, discloses the use of organic thiocyanates to enhance the filterability of biopolymer compositions particularly xanthan gum. U.S. Pat. No. 3,734,187 describes a method of sulfomethylation to alter the viscosity characteristics of polymers to be used in enhanced oil recovery,processes.
U.S. Pat. No. 4,667,026 discloses aqueous solutions of polysaccharide biopolymers (e.g., Xanthomonas/carbohydrate fermentation worts) being heat-treated for more than 5, but less than 60 minutes, at a pH ranging from 3.5 to 6.2, to improve the viscosifying, filterability and injectability properties thereof. The reference indicates that these solutions can be used for secondary and tertiary hydrocarbon (petroleum) recovery by waterflooding therewith.
While many surfactant waterflooding methods have been proposed, there is a substantial, unfulfilled need for a surfactant waterflooding method that is useful in recovering oil from subterranean formations wherein the surfactant(s) employed are utilized at sufficiently low concentration levels to render the method economically feasible. Aside from low concentration levels of surfactants for economic feasibility, it would be useful to provide a composition which includes the surfactants, thickening agents, and other ingredients necessary to formulate an effective waterflooding composition which can be packaged and shipped in the form of a concentrate containing a relatively small amount of water or in a dry or substantially dry state. This would require a concentrate or a dry or substantially dry composition that could be mixed on site with locally available water. Such a concentrate or composition would have to have a reasonable shelf-life and exhibit little or no viscosity or surface activity degradation over time.